Methods of treating a subterranean formation containing hydrocarbons

ABSTRACT

A method of treating a subterranean formation containing hydrocarbons is disclosed, the method comprising: modifying the subterranean formation with a surface energy reducing agent; and injecting into the subterranean formation a fracturing fluid containing a base fluid and a gelling agent; in which the surface energy reducing agent is selected to effectively reduce the surface energy of the subterranean formation to at or below the surface tension of the gelling agent.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit under 35 U.S.C. §119(e) ofProvisional Application No. 61/433,076, filed Jan. 14, 2012.

TECHNICAL FIELD

This document relates to methods of treating a subterranean formationcontaining hydrocarbons.

BACKGROUND

In the conventional fracturing of wells, producing formations, new wellsor low producing wells that have been taken out of production, aformation can be fractured to attempt to achieve higher productionrates. Proppant and fracturing fluid are pumped into a well thatpenetrates an oil or gas bearing formation. High pressure is applied tothe well, the formation fractures and proppant carried by the fracturingfluid flows into the fractures. The proppant in the fractures holds thefractures open after the pressure is relaxed and production is resumed.Various fluids have been disclosed for use as the fracturing fluid,including liquefied petroleum gas (LPG). Various chemicals may be addedto the fracturing fluid, such as gelling agents, breakers, activators,and surfactants.

SUMMARY

A method of treating a subterranean formation containing hydrocarbons isdisclosed, the method comprising: modifying the subterranean formationwith a surface energy reducing agent; and injecting into thesubterranean formation a fracturing fluid containing a base fluid and agelling agent; in which the surface energy reducing agent is selected toeffectively reduce the surface energy of the subterranean formation toat or below the surface tension of the gelling agent.

In various embodiments, there may be included any one or more of thefollowing features: The surface energy reducing agent is selected suchthat the modified subterranean formation does not bond with the gellingagent. The surface energy reducing agent adheres to the subterraneanformation more strongly than the gelling agent adheres to thesubterranean formation. The surface energy reducing agent is selected toeffectively reduce the net force of adhesion between the subterraneanformation and the gelling agent (F_(FG)) from above to below the netforce of cohesion of the gelling agent (F_(GG)). The method comprisesbreaking a gel, formed of the gelling agent, in the subterraneanformation, in which the surface energy reducing agent is selected toeffectively reduce the surface energy of the subterranean formation toat or below the surface tension of the gelling agent when broken.Modifying is carried out by injecting fracturing fluid comprising thesurface energy reducing agent. Modifying comprises coating. The surfaceenergy reducing agent comprises a surfactant. The surfactant comprisesone or more of an ionic surfactant and a non-ionic surfactant. The ionicsurfactant comprises one or more of an anionic surfactant, a cationicsurfactant, and a zwitterionic surfactant. The surface energy reducingagent comprises an alkyne-diol. The surface energy reducing agentcomprises one or more of Surfanol MB, Surfanol 104-PG50, Surfanol 2502,Dynol 604, and Dynol 607. The base fluid comprises hydrocarbons and thegelling agent comprises a gelling agent for hydrocarbons. The gellingagent comprises a polyacrylimide. The gelling agent comprises aphosphate. The base fluid comprises liquefied petroleum gas. The gellingagent comprises a gelling agent for liquefied petroleum gas. The gellingagent is selected to have a surface tension of between twenty andforty-six dynes/cm when in the subterranean formation after breaking.

These and other aspects of the device and method are set out in theclaims, which are incorporated here by reference.

BRIEF DESCRIPTION OF THE FIGURES

Embodiments will now be described with reference to the figures, inwhich like reference characters denote like elements, by way of example,and in which:

FIG. 1A is side elevation view of an apparatus for treating asubterranean formation.

FIG. 1B is a flow diagram of a method of treating a subterraneanformation containing hydrocarbons.

FIG. 2A is an exploded view that illustrates a gelling agent adhering toan untreated formation.

FIG. 2B is an exploded view that illustrates the reduced adherence ofgelling agent to the formation of FIG. 2A after coating, for exampleadsorbing, the formation with surface energy reducing agent.

FIGS. 3A-F are photographs of a formation test surface coated with nosurfactant, Surfanol MB, Surfanol 104-PG50, Surfanol 2502, Dynol 604,and Dynol 607, respectively, immersed in gelled pentane, and spottedwith accudyne pens of varying surface tensions.

DETAILED DESCRIPTION

Immaterial modifications may be made to the embodiments described herewithout departing from what is covered by the claims.

During well treatment, gelling agents or other injected chemicals maystick to the formation on flowback, reducing permeability andpotentially plugging the well. Surface science has identified at leastfive mechanisms of adhesion to explain why one material sticks toanother, namely mechanical adhesion, electrostatic adhesion, chemicaladhesion, dispersive adhesion, and diffusive adhesion. Regarding theadherence of a liquid to a solid or coated solid in a downholeenvironment, the latter three appear most relevant. Chemical adhesionoccurs when two materials form a compound at the join. Ionic, covalent,and hydrogen bonding are examples of chemical adhesion. Diffusiveadhesion occurs when materials merge at the joint by diffusion, forexample if the molecules of the liquid are mobile and soluble in thesolid or liquid coating the solid. Dispersive adhesion, similar tochemical adhesion, occurs when two materials are held together by vander Waals forces, which involve the attraction between slightly chargedmolecules, such as polar compounds. Positive and negative poles may be apermanent property of a molecule (Keesom forces) or a transient effectwhich can occur in any molecule (London forces).

In surface science, adhesion usually refers to dispersive adhesion. In asolid-liquid-gas system (such as a drop of liquid on a solid surroundedby air) contact angle may quantify adhesiveness. In general, where thecontact angle 45 is low (ex. FIG. 2A) more adhesion is present than whenthe contact angle 45 is large (ex. FIG. 2B). The amount of adhesion isrelated to the difference between the surface energy of the surface andthe surface tension of the liquid. Surface energy is the excess energyat the surface of a material compared with the material as a whole.Surface tension refers to the surface energy of a liquid. Regardless,the contact angle of a three-phase system is a function not only ofdispersive adhesion between the molecules in the liquid and themolecules in the solid, but also cohesion, which is dispersiveinteraction between like liquid molecules. Strong adhesion and weakcohesion may result in a high degree of wetting (ex. FIG. 2A), which maybe a lyophilic condition with low measured contact angles. Conversely,weak adhesion and strong cohesion may result in lyophobic conditionswith high measured contact angles and poor wetting (FIG. 2B). Table 1below illustrates surface energies from some example materials.

TABLE 1 Example Surface Energies SURFACE ENERGY/TENSION SURFACE(Dynes/cm) Copper 1,103 Sand 1000 Aluminum 840 Water 72 BrokenPolyacrylimide Gel 35 Hydrocarbons 20-30 Propane <20 Teflon (DuPont) 18

Referring to FIG. 1A, a system 11 for treating a subterranean formation24 containing hydrocarbons is illustrated. Subterranean formation 24 isa hydrocarbon reservoir, which may be treated for example by injectionthrough a well 22 penetrating the hydrocarbon reservoir 24. Fracturingfluid base fluid may be initially contained within a storage tank 10.Tank 10 may comprise a tanker truck or a large vessel.

A generic example treatment of subterranean formation 24 goes asfollows. The fracturing fluid may be pumped from reservoir 10 down line12, where various components may be added to the fluid, for example viaone or more component addition systems 14, 16, 18. For example,components such as gelling agent and proppant may be added from additionsystems 16 and 18, respectively. The addition systems may be, forexample, hoppers. Once the fracturing fluid is prepared and ready, afrac pressure pump 20 injects the frac fluid down a well 22 and intosubterranean formation 24. In some cases, one or more component or fluidmay be added to the frac fluid after the pump 20. The concept ofreservoir treatment is well known, and the details need not be describedhere. In fracturing treatments, pressure may be applied to the fracfluid injected into the subterranean formation 24. The pressure may besufficient to cause fracturing of the subterranean formation.

Referring to FIG. 1B, a method of treating subterranean formation 24 isillustrated. The method will now be described with reference to theother Figures. Referring to FIG. 1A, in a stage 40, the subterraneanformation 24 is modified with a surface energy reducing agent, forexample from addition system 18. Modifying may be carried out byinjecting fracturing fluid comprising the surface energy reducing agent.For example, a pad of base fluid from tank 10 may be combined withsurface energy reducing agent from addition unit 18, and pumped via fracpressure pump 20 down well 22. However, the surface energy reducingagent may also be injected neat or with another suitable fluid. As thesurface energy reducing agent contacts the subterranean formation, thesurface energy reducing agent may coat the formation (FIG. 2B) andeffectively reducing the surface energy of the formation. In someembodiments substantially the entire surface area of the subterraneanformation that will come into contact with the fracturing fluid iscoated. In some cases, the surface energy reducing agent is suppliedthroughout the entire injection of frac fluid. In some embodiments, theproppant used, such as sand, may be pre-coated or co-injected withsurface energy reducing agent. Coating a surface reduces roughness ofthe coated surface and thus is beneficial as adherence may increase withgreater degrees of roughness.

In a stage 42, a fracturing fluid containing a base fluid, for examplefrom tank 10, and a gelling agent, for example from addition unit 16, isinjected into the subterranean formation 24. The treatment, which may bea fracturing treatment, may then be completed, for example by pressuringup the fluid in well 22 to frac, and delivering proppant from additionunit 16 into the fractures formed in the subterranean formation.

Referring to FIGS. 2A and 2B, the effect of the surface energy reducingagent 44 will now be described. FIG. 2A illustrates a situation wherethe injected gelling agent 46 has a surface tension that is lower thanthe surface energy of the formation 24. As is shown, a contact angle 45less than 90 degrees indicates high adherence. In most formations, forexample sandstone formations, the surface energy of the formation 24will be larger than the surface tension of the gelling agent 46,effectively causing gelling agent 46 to wet and adhere to the formation24. FIG. 2B illustrates the beneficial effect of the surface energyreducing agent 44, which has been selected to effectively reduce thesurface energy of the formation 24 to at or below the surface tension ofthe gelling agent 46. In FIG. 2B, the contact angle 45 is greater than90 degrees, indicating a low degree of wetting, and likely a low degreeof adherence. Thus, for a polymer gel such as polyacrylamide gel with asurface tension of 35, the surface energy reducing agent 44 must reducethe surface energy to thirty-five dynes/cm or lower, for example down totwenty dynes/cm. In most cases, the desired result will be achieved ifthe surface energy reducing agent 44 is selected to reduce the net forceof adhesion between the subterranean formation 24 and the gelling agent(F_(FG)) from above to below the net force of cohesion of the gellingagent (F_(GG)).

The surface energy reducing agent 44 may be selected such that themodified subterranean formation shown in FIG. 2B does not bond, forexample chemically, with the gelling agent 46. For example, the surfaceenergy reducing agent 44 may be selected to form a hydrophobic coatingif the gelling agent 46 is known to be hydrophilic. Thus, when the fracpressure is reduced and flowback induced, gelling agent 46 is able toslide off of formation 24 and be removed from the well 22. The surfaceenergy reducing agent 44 may also be selected to adhere to thesubterranean formation 24 more strongly than the gelling agent 46adheres to the subterranean formation 24. Thus, diffusion of the gellingagent 46 into the thin film coating formed by the surface energyreducing agent 46 does not result in gelling agent 46 displacing surfaceenergy reducing agent 44 and adhering to the formation 24. However, insome cases this is not required, and a thin low adherence film ofsurface energy reducing agent may be sufficient to allow substantialremoval of gelling agent and related chemicals from the well 22.

The gelling agent 46 selected may have a surface tension of betweentwenty and forty-six dynes/cm when in the subterranean formation afterbreaking. In some cases the method includes the stage of breaking a gel,formed of the gelling agent 46, in the subterranean formation 24, inwhich the surface energy reducing agent 44 is selected to effectivelyreduce the surface energy of the subterranean formation 24 to at orbelow the surface tension of the gelling agent 46 when broken. Thus, thebroken gelling agent is targeted by the surface energy reducing agent44, as it is broken gel that may be left in formation 24. This may be aconsideration if the gelling agent changes surface tension upon breakingdue to a chemical change in the gelling agent. The surface energyreducing agent may make the formation 24 omniphobic, in order to alloweasy removal of the base fluid as well as the fracturing chemicals.

Referring to FIGS. 3A-F, the surface energy reducing agent may comprisea surfactant, such as an alkyne-diol. Accudyne testing was carried outon a formation 24 sample immersed in pentane gelled with 16 L/m³ gel, 16L/m³ activator, and 8 L/m³ breaker. The formation sample tested was ashale sample from Alberta. In this test, a surface energy reducing agentwas introduced and coated on formation 24 sample. Afterwards, accudynepens of different surface tensions were spotted on the formation 24sample, in order to determine if surface energy had been reduced. Ingeneral, a solid spot produced by a pen with a surface tension Xindicates that the formation has a surface energy above X, while asplotchy or beaded spot produced by the same pen indicates low adherencedue to the fact that the formation has a surface energy at or below X.For ease of illustration, reference numerals 54, 56, 58, 60, 62, and 64identify spots made by accudyne pens of surface tensions 30, 32, 34, 36,38, and 40 dynes/cm, respectively. FIG. 3A was used as a blank formationsample 24, with no surface energy reducing agent added to the gelledpentane. In FIGS. 3B-F, the surface energy reducing agent comprisesSurfanol MB (FIG. 3B), Surfanol 104-PG50 (FIG. 3C), Surfanol 2502 (FIG.3D), Dynol 604 (FIG. 3E), and Dynol 607 (FIG. 3F). In FIG. 3A where nosurface energy reducing agent was used, accudyne pens having surfacetensions 34 dynes/cm and 36 dynes/cm were able to clearly form solidspots 58 and 60, respectively, indicating that the surface energy offormation sample 24 was at least greater than 36 dynes/cm and likelymuch higher. By contrast, the surfactants used in FIGS. 3B-F alleffectively reduced the surface energy of formation 24 sample, asevidenced by the beaded spots left by most of the pens. The followingTable 2 indicates the estimated effective surface energy of the modifiedformation 24 samples based on the tesing.

TABLE 2 Accudyne Test Results Effective Surface Energy of Fig.Surfactant added Modified Formation 24 Sample 3A none >36 (likely muchhigher) 3B Surfanol MB <30 3C Surfanol 104-PG50 <30 3D Surfanol 250234-36 3E Dynol 604 32-34 3F Dynol 607 <30

The base fluid may comprise hydrocarbons, such as C₆-C₂₀ hydrocarbons,and the gelling agent may comprise a gelling agent for hydrocarbons. Thegelling agent may comprise a phosphate based chemical. In other casesthe base fluid may be water, and the gelling agent may be a gellingagent for water. The base fluid may comprise liquefied petroleum gas,and the gelling agent may comprise a gelling agent for liquefiedpetroleum gas. LPG has been advantageously used as a fracturing fluid tosimplify the recovery and clean-up of frac fluids after a frac.Exemplary LPG frac systems are disclosed in WO2007098606, incorporatedherein by reference. One example of a suitable gelling agent for LPG iscreated by first reacting diphosphorous pentoxide with triethylphosphate and an alcohol having hydrocarbon chains of 3-7 carbons long,or in a further for example alcohols having hydrocarbon chains 4-6carbons long. The orthophosphate acid ester formed is then reacted withaluminum sulphate to create the desired gelling agent. The gelling agentcreated will have hydrocarbon chains from 3-7 carbons long or, as in thefurther example, 4-6 carbons long. The hydrocarbon chains of the gellingagent are thus commensurate in length with the hydrocarbon chains ofliquid petroleum gas used for the frac fluid. This gelling agent is moreeffective at gelling a propane or butane fluid than a gelling agent withlonger hydrocarbon chains. The proportion of gelling agent in the fracfluid is adjusted to obtain a suitable viscosity in the gelled fracfluid.

In some embodiments, a volatile-phosphorus free gelling agent may beused, for example for gelling hydrocarbons. Such a gelling agent mayhave the general formula of:

where X is an OR¹, NR¹R², or SR¹ group, R¹ is an organic group having2-24 carbon atoms, and R² is an organic group or a hydrogen. Y is anNR³R⁴ or SR³ group, R³ is an organic group having 2-24 carbon atoms, andR⁴ is an organic group or a hydrogen. Such gelling agent may be made asfollows. Phosphorus oxyhalide is reacted with a chemical reagent toproduce substantially only diester phosphorus oxyhalide, the chemicalreagent comprising at least one of an organic alcohol having 2-24 carbonatoms, an organic amine with an organic group having 2-24 carbon atoms,and an organic sulfide having 2-24 carbon atoms. The diester phosphorusoxyhalide is then hydrolyzed to produce diester phosphoric acid. Furtherexamples are given in WO/2010/022496, incorporated herein by reference.

LPG may include a variety of petroleum and natural gases existing in aliquid state at ambient temperatures and moderate pressures. In somecases, LPG refers to a mixture of such fluids. These mixes are generallymore affordable and easier to obtain than any one individual LPG, sincethey are hard to separate and purify individually. Unlike conventionalhydrocarbon based fracturing fluids, common LPGs are tightlyfractionated products resulting in a high degree of purity and verypredictable performance. Exemplary LPGs include ethane, propane, butane,or various mixtures thereof. As well, exemplary LPGs also includeisomers of propane and butane, such as iso-butane. Further LPG examplesinclude HD-5 propane, commercial butane, and n-butane. The LPG mixturemay be controlled to gain the desired hydraulic fracturing and clean-upperformance. LPG fluids used may also include minor amounts of pentane(such as i-pentane or n-pentane), and higher weight hydrocarbons.

LPGs tend to produce excellent fracturing fluids. LPG is readilyavailable, cost effective and is easily and safely handled on surface asa liquid under moderate pressure. LPG is completely compatible withformations and formation fluids, is highly soluble in formationhydrocarbons and eliminates phase trapping—resulting in increased wellproduction. LPG may be readily and predictably viscosified to generate afluid capable of efficient fracture creation and excellent proppanttransport. After fracturing, LPG may be recovered very rapidly, allowingsavings on clean up costs. In some embodiments, LPG may be predominantlypropane, butane, or a mixture of propane and butane. In someembodiments, LPG may comprise more than 80%, 90%, or 95% propane,butane, or a mixture of propane and butane.

Exemplary gelling agents that may be used are disclosed by Whitney inU.S. Pat. Nos. 3,775,069 and 3,846,310, the specifications of which areincorporated by reference. Such gelling agents may createwater-sensitive gels. An example of a suitable gelling agent comprises acombination of an alkoxide of a group IIIA element and an alkoxide of analkali metal. When combined, the alkoxide of the group IIIA element andthe alkoxide of the alkali metal react to form a polymer gel. The groupIIIA element may comprise one or more of boron and aluminum for example.In some embodiments, the alkoxide of a group IIIA element comprisesM¹(OR¹)(OR²)(OR³), in which M¹=the group IIIA element, and R¹, R², andR³ are organic groups. Each of the organic groups of R¹, R², and R³ mayhave 2-10 carbon atoms, and may comprise an alkyl group. In oneembodiment, M¹=boron, and R¹, R², and R³ comprise 2-10 carbon atoms. Thealkali metal may comprise one or more of lithium, sodium, and potassiumfor example. In some embodiments, the alkoxide of an alkali metalfurther comprises M²(OR⁴), in which M²=the alkali metal, and R⁴comprises an organic group. The organic group of R⁴ may comprise 2-24carbon atoms, for further example 12 carbon atoms, and may comprise analkyl group. In one embodiment, M²=lithium and the organic group of R⁴comprises 2-24 carbon atoms. In some embodiments, R⁴ may furthercomprise: (AQ)_(n)(R⁵)_(x)(R⁶)_(y). in which A is an organic group, Q isO or N, n is 1-10, R⁵ and R⁶ are organic groups, x is either 1 or 2depending on the valence of Q, and y is 0 or 1 depending on the valenceof Q. Thus, the alkoxide of an alkali metal formed would have theformula of M²O(AQ)_(n)(R⁵)_(x)(R)_(y). A may have 2-4 carbon atoms. Theorganic groups of R⁵ and R⁶ may each have 1-16 carbons. Where y=1, R⁶ isbonded to the Q atom. Organic groups as disclosed herein may refer togroups with at least one carbon atom, as long the resulting gellingagent is suitable for its purpose. Examples of organic groups includephenyl, aryl, alkenyl, alkynyl, cyclo, and ether groups. A suitableamount of gelling agent may be used, for example 0.25-5% by weight ofthe fracturing fluid. In addition, the a suitable ration of the alkoxideof a group IIIA element and the alkoxide of an alkali metal may be used,for example 3:1 to 1:3, with 1:1 being a preferable ratio.

The following exemplary procedure may be used to form a fracturing fluidcontaining a water sensitive gel as discussed in the precedingparagraph. Butyl lithium (3.53 mL of a 1.7 M solution in pentane, 6mmol) was added dropwise to a stirring solution of dodecanol (1.12 g, 6mmol) in pentane (125.00 g, 1% by wt gelling agents in pentane). Thismixture was then stirred for a further 1 h at room temperature. Aseparate solution of tributyl borate (1.62 mL, 6 mmol) in pentane(125.00 g) was prepared in a blender at 17% variance with a rheostat for5 min. To this solution was added the lithium alkoxide solution and ahydrated breaker, for example CaSO₄(2H₂O) (2.91 g, 0.15% by vol. H2O, 60mesh) Blending was continued for 1 min at 30% variance. Over this timecloudy white gels formed. These were tested on a Brookfieldviscometer-60° C., 4 h, 110 psi.

Exemplary breakers for use with water-sensitive gels include hydratedbreakers. For example, the hydrated breaker may comprise one or morehydrates, wherein water of the one or more hydrates is releasable so asto act with the water-sensitive carrier to reduce the viscosity of thefracturing fluid. A hydrated breaker may have a crystalline frameworkcontaining water that is bound within the crystalline framework andreleasable into the fracturing fluid to act on the water-sensitive gelto reduce the viscosity of the fracturing fluid. Hydrated breakers aredisclosed for example in U.S. application Ser. No. 12/609,893 and CAApplication No. 2685298 the content of which is incorporated here byreference where permitted by law.

In some embodiments, a gelling agent need not be specifically targetedby the surface energy reducing agent. For example, the surface energyreducing agent may be selected to effectively reduce the surface energyof the subterranean formation to at or below the surface tension of oneor more of the base fluid, breaker, activator, gelling agent, or othertreating chemical. Thus, the targeted injected chemicals may be easilyremoved after treatment is complete, and potential for well damage bytacky chemicals is reduced or eliminated.

Various surfactants may be used as the surface energy reducing agent.For example, the surfactant may comprise one or more of an ionicsurfactant and a non-ionic surfactant. For further example, if used theionic surfactant may comprise one or more of an anionic surfactant, acationic surfactant, and a zwitterionic surfactant.

Anionic surfactants may be based on permanent anions such as sulfate,sulfonate, and phosphate, or pH-dependent anions such as carboxylate.Example anionic surfactants based on sulfates include alkyl sulfatessuch as ammonium lauryl sulfate and sodium lauryl sulfate (SDS), alkylether sulfates such as sodium laureth sulfate (also known as sodiumlauryl ether sulfate or SLES), and sodium myreth sulfate. Exampleanionic surfactants based on sulfonates include docusates such asdioctyl sodium sulfosuccinate. Example anionic surfactants based onsulfonates also include sulfonate fluorosurfactants such asperfluorooctanesulfonate (PFOS), and perfluorobutanesulfonate. Exampleanionic surfactants based on sulfonates also include alkyl benzenesulfonates. Example anionic surfactants based on phosphates includealkyl aryl ether phosphate and alkyl ether phosphate. Example anionicsurfactants based on carboxylates include alkyl carboxylates such asfatty acid salts (soaps) and sodium stearate. Example anionicsurfactants based on carboxylates also include sodium lauroylsarcosinate. Example anionic surfactants based on carboxylates alsoinclude carboxylate fluorosurfactants such as perfluorononanoate, andperfluorooctanoate (PFOA or PFO).

Cationic surfactants may be based on pH-dependent amines or permanentlycharged quaternary ammonium cations. Example cationic surfactants basedon pH-dependent amines include primary, secondary or tertiary amines.For example, primary amines may be used that become positively chargedat pH<10, and secondary amines may be used that become charged at pH<4.One example of a pH-dependent amine is octenidine dihydrochloride.Example cationic surfactants based on permanently charged quaternaryammonium cations include alkyltrimethylammonium salts such as cetyltrimethylammonium bromide (CTAB a.k.a. hexadecyl trimethyl ammoniumbromide), and cetyl trimethylammonium chloride (CTAC). Example cationicsurfactants based on permanently charged quaternary ammonium cationsalso include cetylpyridinium chloride (CPC), polyethoxylated tallowamine (POEA), benzalkonium chloride (BAC), benzethonium chloride (BZT),5-bromo-5-nitro-1,3-dioxane, dimethyldioctadecylammonium chloride, anddioctadecyldimethylammonium bromide (DODAB).

Zwitterionic surfactants, which may be amphoteric, may be based onprimary, secondary or tertiary amines or quaternary ammonium cationswith sulfonate, carboxylate, or phosphate anions. Example zwitterionicsurfactants with sulfonates include CHAPS(3-[(3-Cholamidopropyl)dimethylammonio]-1-propanesulfonate), andsultaines such as cocamidopropyl hydroxysultaine. Example zwitterionicsurfactants with carboxylates include amino acids, imino acids, andbetaines such as cocamidopropyl betaine. Example zwitterionicsurfactants with phosphates include lecithin.

Nonionic surfactants may include fatty alcohols such as cetyl alcohol,stearyl alcohol, cetostearyl alcohol (for example comprisingpredominantly of cetyl and stearyl alcohols), and oleyl alcohol.Nonionic surfactants may also include polyoxyethylene glycol alkylethers (Brij or CH₃—(CH₂)₁₀₋₁₆—(O—C₂H₄)₁₋₂₅—OH) such as octaethyleneglycol monododecyl ether, and pentaethylene glycol monododecyl ether.Nonionic surfactants may also include polyoxypropylene glycol alkylethers (CH₃—(CH₂)₁₀₋₁₆—(O—C₃H₆)₁₋₂₅—OH). Nonionic surfactants may alsoinclude glucoside alkyl ethers (CH₃—(CH₂)₁₀₋₁₆—(O-Glucoside)₁₋₃-OH) suchas decyl glucoside, lauryl glucoside, and octyl glucoside. Nonionicsurfactants may also include polyoxyethylene glycol octylphenol ethers(C₈H₁₇—(C₆H₄)—(O—C₂H₄)₁₋₂₅—OH) such as Triton X-100. Nonionicsurfactants may also include polyoxyethylene glycol alkylphenol ethers(C₉H₁₉—(C₆H₄)—(O—C₂H₄)₁₋₂₅—OH) such as nonoxynol-9. Nonionic surfactantsmay also include glycerol alkyl esters such as glyceryl laurate.Nonionic surfactants may also include polyoxyethylene glycol sorbitanalkyl esters such as polysorbates. Nonionic surfactants may also includesorbitan alkyl esters such as spans. Nonionic surfactants may alsoinclude cocamide MEA, and cocamide DEA. Nonionic surfactants may alsoinclude dodecyl dimethylamine oxide, and block copolymers ofpolyethylene glycol and polypropylene glycol such as poloxamers.

TABLE 3 Accudyne Test Results on non-ionic, anionic, and cationicsurfactants in gelled LPG (LP10). Effective Surface Energy of Surfactantadded Modified Formation 24 Sample 1-hexadecanol (non-ionic) 34-36Sodium dodecyl sulfate (anionic) 32-34 Benzalkonium Chloride (cationic)38-40

LP10 is a broken dialkyl phosphate LPG gel.

In the claims, the word “comprising” is used in its inclusive sense anddoes not exclude other elements being present. The indefinite article“a” before a claim feature does not exclude more than one of the featurebeing present. Each one of the individual features described here may beused in one or more embodiments and is not, by virtue only of beingdescribed here, to be construed as essential to all embodiments asdefined by the claims.

1. A method of treating a subterranean formation containinghydrocarbons, the method comprising: modifying the subterraneanformation with a surface energy reducing agent; and injecting into thesubterranean formation a fracturing fluid containing a base fluid and agelling agent; in which the surface energy reducing agent is selected toeffectively reduce the surface energy of the subterranean formation toat or below the surface tension of the gelling agent.
 2. The method ofclaim 1 in which the surface energy reducing agent is selected such thatthe modified subterranean formation does not bond with the gellingagent.
 3. The method of claim 1 in which the surface energy reducingagent adheres to the subterranean formation more strongly than thegelling agent adheres to the subterranean formation.
 4. The method ofclaim 1 in which the surface energy reducing agent is selected toeffectively reduce the net force of adhesion between the subterraneanformation and the gelling agent (F_(FG)) from above to below the netforce of cohesion of the gelling agent (F_(GG)).
 5. The method of claim1 further comprising breaking a gel, formed of the gelling agent, in thesubterranean formation, in which the surface energy reducing agent isselected to effectively reduce the surface energy of the subterraneanformation to at or below the surface tension of the gelling agent whenbroken.
 6. The method of claim 1 in which modifying is carried out byinjecting fracturing fluid comprising the surface energy reducing agent.7. The method of claim 1 in which modifying comprises coating.
 8. Themethod of claim 1 in which the surface energy reducing agent comprises asurfactant.
 9. The method of claim 8 in which the surface energyreducing agent comprises an alkyne-diol.
 10. The method of claim 8 inwhich the surface energy reducing agent comprises one or more ofSurfanol MB, Surfanol 104-PG50, Surfanol 2502, Dynol 604, and Dynol 607.11. The method of claim 8 in which the surfactant comprises one or moreof an ionic surfactant and a non-ionic surfactant.
 12. The method ofclaim 11 in which the ionic surfactant comprises one or more of ananionic surfactant, a cationic surfactant, and a zwitterionicsurfactant.
 13. The method of claim 1 in which the base fluid compriseshydrocarbons and the gelling agent comprises a gelling agent forhydrocarbons.
 14. The method of claim 13 in which the gelling agentcomprises a polyacrylimide.
 15. The method of claim 1 in which the basefluid comprises liquefied petroleum gas.
 16. The method of claim 15 inwhich the gelling agent comprises a gelling agent for liquefiedpetroleum gas.
 17. The method of claim 1 in which the gelling agent isselected to have a surface tension of between twenty and forty-sixdynes/cm when in the subterranean formation after breaking.